Pengfei Dong, Maura Puerto, and Guoqing Jian, Rice University; Kun Ma, Khalid Mateen, Guangwei Ren, Gilles Bourdarot, Danielle Morel, and Maurice Bourrel, Total E&P; and Sibani Lisa Biswal and George Hirasaki, Rice University Summary Oil recovery in heterogeneous carbonate reservoirs is typically inefficient because of the presence of high-permeability fracture networks and unfavorable capillary forces within the oil-wet matrix. Foam, as a mobility-control agent, has been proposed to mitigate the effect of reservoir heterogeneity by diverting injected fluids from the high-permeability fractured zones into the low-permeability unswept rock matrix, hence improving the sweep efficiency. This formulation provides both mobility control and oil/water IFT reduction to overcome the unfavorable capillary forces preventing invading fluids from entering an oil-filled matrix. Thus, as expected, the combination of mobility control and low-IFT significantly improves oil recovery compared with either foam or surfactant flooding. A three-component surfactant formulation was tailored using phase-behavior tests with seawater and crude oil from a targeted reservoir. N/m and strong foam in porous media when oil is present. Foam flooding was investigated in a representative fractured core system, in which a well-defined fracture was created by splitting the core lengthwise and precisely controlling the fracture aperture by applying a specific confining pressure. The foam-flooding experiments reveal that, in an oil-wet fractured Edward Brown dolomite, our low-IFT foaming formulation recovers approximately 72% original oil in place (OOIP), whereas waterflooding recovers only less than 2% OOIP; moreover, the residual oil saturation in the matrix was lowered by more than 20% compared with a foaming formulation lacking a low-IFT property. The selective diversion effect of this low-IFT foaming system effectively recovers the trapped oil, which cannot be recovered with single surfactant or high-IFT foaming formulations applied to highly heterogeneous or fractured reservoirs. Introduction Carbonate reservoirs are thought to hold approximately 60% of crude oil and 40% of natural-gas reserves in the world (Akbar et al. 2000). However, oil recovery in carbonate reservoirs poses great challenges to the petroleum industry. These fracture networks provide a bypass, usually called a thief zone, for the fluids injected into the reservoirs. In addition, approximately 80 to 90% of carbonate reservoirs are intermediate-wet or oil-wet (Treiber and Owens 1972; Chilingar and Yen 1983), resulting in an unfavorable condition for spontaneous imbibition by capillary forces (Hirasaki and Zhang 2004). These characteristics of carbonate reservoirs cause low sweep and displacement efficiency and, hence, low oil-recovery rates.

Oil recovery in many carbonate reservoirs is challenging due to unfavorable conditions such as oil-wet surface wettability, high reservoir heterogeneity and high brine salinity. We present the feasibility and injection strategy investigation of ultralow-interfacial-tension (ultralow-IFT) foam in a high temperature (above 80°C), ultra-high formation salinity (above 23% TDS) fractured carbonate reservoir.

Because a salinity gradient is generated between injection sea water (4.2% TDS) and formation brine (23% TDS), a frontal-dilution map was created to simulate frontal displacement processes and thereafter used to optimize surfactant formulations. IFT measurements and bulk foam tests were also conducted to study the salinity gradient effect to ultralow-IFT foam performance. Ultralow-IFT foam injection strategies were investigated through a series of core flood experiments in both homogenous and fractured core systems with initial two-phase saturation. The representative fractured system included a well-defined fracture by splitting core sample lengthwise and controllable initial oil/brine saturation in the matrix by closing the fracture with a rubber sheet at high confining pressure.

The surfactant formulation showed ultra-low IFT (10-2-10-3 mN/m magnitude) at the displacement front and good foamability at under-optimum conditions. Both ultralow-IFT and foamability properties were found to be sensitive to the salinity gradient. Ultralow-IFT foam flooding achieved over 60% incremental oil recovery compared to water flooding in oil-wet fractured systems due to the selective diversion of ultralow-IFT foam. This effect resulted in crossflow near foam front, with surfactant solution (or weak foam) primarily diverted from the fracture into the matrix before the foam front, and oil/high-salinity brine flowed back to the fracture ahead of the front. The crossflow of oil/high-salinity brine from the matrix to the fracture was found to make it challenging for foam propagation in the fractured system by forming Winsor II condition near foam front and hence killing the existing foam.

Results in this work demonstrated the feasibility of ultralow-IFT foam in high temperature, ultra-high salinity fractured carbonate reservoirs and investigated the injection strategy to enhance the low-IFT foam performance. The ultralow-IFT formulation helped mobilize the residual oil for better displacement efficiency. The selective diversion of foam makes it a good candidate as a mobility control agent in fractured system for better sweep efficiency.

In this paper, we will highlight some of the impactful collaborative efforts completed within DeepStar Phase XII of the X200 Flow Assurance committees leading to the development, integration and deployment of novel technologies.

This project aims to establish in what cases asphaltene deposition in reservoirs is a real problem. Flow reduction can occur in deepwater wells, which manifests as effective "skin" or high pressure drawdown required for fluid flow to be maintained. It is typically concluded, without additional evidence, that such problems are the result of asphaltene deposition. Some models for asphaltene deposition were developed between 1990 and 2005. However, the principal obstruction to validation of these models has been a credible core flow test to show increased flow restriction with depositing asphaltenes.

At present, operators are unable to estimate the risk of development due to asphaltene deposition in reservoirs and the perceived flow impairment. To best assess the treatment frequency and effectiveness that is required for project development and execution, there is a need to be able to correctly predict the rate of formation damage in reservoirs from asphaltene deposition and develop effective remediation treatments. A successful project will provide test protocol, results, and analysis tools that can be applied to risk management evaluation for asphaltene fouling in reservoirs.

Asphaltene precipitation and deposition in the production tubing and surface facilities is a well- documented issue and different methods are available to manage this problem. However, the problems that asphaltenes may cause in the reservoir, especially in the near-wellbore region, are much less understood. There is a lack of experimental capability to properly identify this problem and evaluate the corresponding potential strategies for prevention and/or remediation if/when needed. In addition, the available modeling tools to account for this problem have limited capabilities. Within this project, we aim to develop experimental procedures and modeling methods to establish whether impairment caused by asphaltene deposition in reservoirs is a real problem or not, and to develop an understanding of the mechanisms by which asphaltene precipitate, alter wettability and potentially deposit in the formation obstructing flow.

A new experimental setup for Saturates, Aromatics, Resins, and Asphaltenes (SARA) characterization was designed and implemented in the lab to perform faster and more reliable analyses. Core flood experiments have been designed and successfully executed to induce the precipitation of asphaltenes inside the core upon addition of an asphaltene precipitant (e.g., n-pentane or n-heptane), which is crucial to obtain more meaningful and more representative experimental conditions. It has been observed that when n-pentane is used to precipitate asphaltenes, even though asphaltene aggregates are present in the system, the core flood test results do not show apparent damage to permeability. However, when asphaltenes are precipitated upon addition of n-heptane, aggregates have a more solid-like structure, which in turn have more tendency to block the pore throats. A microfluidic device was developed and used to visualize asphaltene deposition in porous media, at ambient pressure and different temperatures, flow rates, and driving force of asphaltene precipitation. The test results obtained from microfluidic device are in good agreement with the test results from the core flood experiments. A Computational Fluid Dynamic model based on Lattice-Boltzmann theory was developed to simulate asphaltene deposition inside porous media and is being validated for the capability to scale up lab results to field conditions.

In this paper, we will highlight some of the impactful collaborative efforts completed within DeepStar Phase XII of the X200 Flow Assurance committees leading to the development, integration and deployment of novel technologies. This project aims to establish in what cases asphaltene deposition in reservoirs is a real problem. Flow reduction can occur in deepwater wells, which manifests as effective "skin" or high pressure drawdown required for fluid flow to be maintained. It is typically concluded, without additional evidence, that such problems are the result of asphaltene deposition. Some models for asphaltene deposition were developed between 1990 and 2005. However, the principal obstruction to validation of these models has been a credible core flow test to show increased flow restriction with depositing asphaltenes. At present, operators are unable to estimate the risk of development due to asphaltene deposition in reservoirs and the perceived flow impairment. To best assess the treatment frequency and effectiveness that is required for project development and execution, there is a need to be able to correctly predict the rate of formation damage in reservoirs from asphaltene deposition and develop effective remediation treatments. A successful project will provide test protocol, results, and analysis tools that can be applied to risk management evaluation for asphaltene fouling in reservoirs. Asphaltene precipitation and deposition in the production tubing and surface facilities is a well- documented issue and different methods are available to manage this problem. However, the problems that asphaltenes may cause in the reservoir, especially in the near-wellbore region, are much less understood. There is a lack of experimental capability to properly identify this problem and evaluate the corresponding potential strategies for prevention and/or remediation if/when needed. In addition, the available modeling tools to account for this problem have limited capabilities. Within this project, we aim to develop experimental procedures and modeling methods to establish whether impairment caused by asphaltene deposition in reservoirs is a real problem or not, and to develop an understanding of the mechanisms by which asphaltene precipitate, alter wettability and potentially deposit in the formation obstructing flow. A new experimental setup for Saturates, Aromatics, Resins, and Asphaltenes (SARA) characterization was designed and implemented in the lab to perform faster and more reliable analyses. Core flood experiments have been designed and successfully executed to induce the precipitation of asphaltenes inside the core upon addition of an asphaltene precipitant (e.g., n-pentane or n-heptane), which is crucial to obtain more meaningful and more representative experimental conditions. It has been observed that when n-pentane is used to precipitate asphaltenes, even though asphaltene aggregates are present in the system, the core flood test results do not show apparent damage to permeability. However, when asphaltenes are precipitated upon addition of n-heptane, aggregates have a more solid-like structure, which in turn have more tendency to block the pore throats. A microfluidic device was developed and used to visualize asphaltene deposition in porous media, at ambient pressure and different temperatures, flow rates, and driving force of asphaltene precipitation. The test results obtained from microfluidic device are in good agreement with the test results from the core flood experiments. A Computational Fluid Dynamic model based on Lattice-Boltzmann theory was developed to simulate asphaltene deposition inside porous media and is being validated for the capability to scale up lab results to field conditions.

Oil recovery in highly heterogeneous carbonate reservoirs is typically inefficient because of the high permeable fracture networks and unfavorable capillary force resulting from oil-wet matrix. Foam as a mobility control agent has been proposed to mitigate reservoir heterogeneity by diverting injected fluids from the highly permeable fractured zones into the low permeable unswept rock matrix, hence improving the sweep efficiency. This paper presents the use of a low-interfacial-tension foaming formulation to improve oil recovery in highly heterogeneous/fractured oil-wet carbonate reservoirs. The novel formulation providesboth mobility control and oil-water interfacial tension (IFT) reduction to overcome the unfavorable capillary forces preventingdisplacing fluids from entering oil-filled matrix. Thus, as expected, the combination of these two effects significantly improves oil recovery compared to either foam or surfactant flooding.

In this research, the three-component surfactant formulation was tailored by phase behavior tests in seawater with crude oil from a targeted reservoir. The optimized formulation can simultaneously generate 10−2 mN/m IFT and strong foam in porous media with oil present, as demonstrated by IFT measurements and foam floodingtests. Foam flooding was investigated in a representative fractured core system, in which a well-defined fracture was created by splitting core lengthwise and precisely controlled of aperture by applying specific confining pressure. The foam flooding experiments reveal that the low-IFT foaming formulation in an oil-wet fractured Edward Brown dolomite recovers about 72% of oil while water flooding only recovers less than 2%,and it is more efficient than foam flooding lacking low oil-water IFT property.The core flood test results also indicate that low-IFT foam diverts mostly surfactant solution into matrix because of (1) the mobility reduction due to foam in the fracture network, (2) significantly lower capillary entry pressure for surfactant solution compared to gas and (3) the increase of mobility to water in the matrix by the low oil-water IFT displacing residual oil in the matrix. This selective diversion effect of the novel foaming system allows to carry out the surfactant flooding at low IFT condition in the low permeability matrix to recover the trapped oil, which is otherwise impossible with simple surfactant or high-IFT foam flooding in highly heterogeneous or fractured reservoirs.

In the absence of oil in the porous medium, the STARSTM foam model has three parameters to describe the foam quality dependence, , , and . Even for a specified value of , two pairs of values of and can sometimes match experimentally measured and . This non-uniqueness can be broken by limiting the solution to the one for which < . Additionally, a three-parameter search is developed to simultaneously estimate the parameters , , and that fit the transition foam quality and apparent viscosity. However, a better strategy is to conduct and match a transient experiment in which 100% gas displaces surfactant solution at 100% water saturation. This transient foam quality scans the entire range of fractional flow and the values of the foam parameters that best match the experiment can be uniquely determined. Finally, a three-parameter fit using all experimental data of apparent viscosity versus foam quality is developed.

The numerical artifact of pressure oscillations in simulating this transient foam process is investigated by comparing finite difference algorithm with method of characteristics. Sensitivity analysis shows that the estimated foam parameters are very dependent on the parameters for the water and gas relative permeability. In particular, the water relative permeability exponent and connate water saturation are important.